International Petroleum Research Articles

First Multistage Fracturing of a Horizontal Well Drilled in a Tight Carbonate Reservoir in UAE

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203226, “First Multistage Fracturing of Horizontal Well Drilled in a Conventional Tight Carbonate Reservoir in an Onshore Field in the UAE: Challenges and Lessons Learned,” by Muhammad Aftab, SPE, Noor Talib, and Maad Subaihi, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The reservoir upon which this case study is focused is a tight, low-permeability carbonate reservoir with thin layers. The objective of the field case was to increase and sustain productivity of a pilot well consisting of an openhole completion. The complete paper summarizes the design processes, selection criteria, challenges, and lessons learned during design and execution phases. The study may provide a potential approach for selecting the proper hydraulic fracturing method and technique in similar cases. Introduction Reservoir X is divided into six layers. Layers X-3 through X-6 have reasonable porosity development; valid pressure points exist in X-3 and X-6. Pumpout was performed while collecting samples from X-3 and X-6, followed by short buildups. Production-logging-tool measurement was performed and found two major oil-producing layers across X-3 (60% of total production) and X-6 (40% of total production). The remaining intervals of the perforation were almost inactive. Petrophyscial and testing results of vertical Well A resulted in a decision to drill a horizontal oil producer (Well B) through Layer X-3. Well B was steered with a 2,220-ft horizontal length, out of which 1,930 ft was inside X-3 and 290 ft were above X-3 be-cause of a fault throw of 16 ft true vertical depth. The well was steered with a horizontal length of 2,080 ft in X-6. Well B was completed with a 3½-in. completion and horizontal section as an openhole. Matrix stimulation using coiled tubing was performed with 15% hydrochloric acid in Well B. The well ceased to flow after 2 weeks of declining production. Rapid pressure depletion was observed in Well B. Localized depletion around the wellbore was anticipated because of poor matrix/matrix connectivity. After comprehensive studies and risk assessments, the decision was made to recomplete Well B with a cemented fracturing string to perform hydraulic fracturing with the plug-and-perf technique. This technique will allow flexibility of stage count and stage spacing and a multi-cluster design to maximize the stimulated reservoir volume (SRV) along the upper, middle, and lower layers. In addition, the operator and service provider collaborated to enhance this design through a zero-overflush technique with diverting agents. The complete paper provides a detailed discussion of the core measurement and 1D mechanical Earth model used in the hydraulic fracturing design. Hydraulic Fracturing Design The main challenge in fracturing Well B was to ensure that the fracture generated is contained within the reservoir. Well B is completed in two layers (X-3 and X-6). The bottom part of the well is in X-6 and close to another underlying reservoir (Fig. 1).

Reservoir Stimulation Technique Combines Radial Drilling Technology With Acid Jetting

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202661, “Combination of Radial Drilling Technology With Acid Jetting: New Approach in Carbonate Reservoir Stimulation,” by Ayrat Bashirov, Ilya Lyagov, and Ilya Galas, Perfobur, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The complete paper describes an approach to stimulate carbonate formations with bedding water or a gas cap. The technique is a combination of acid jetting and a radial drilling technology that uses mechanical radial drilling with a slim mud motor. The primary advantages of the technology include controlled trajectory and the possibility of re-entry into channels. The novelty of the technology is in its ability to deploy acids in the rock far away from the wellbore through the mechanically drilled holes with known depths and azimuths. Reservoir Description The mature field is in central Russia in the Republic of Bashkortostan. The field contains both sandstone and carbonate reservoirs. Oil depth is from 780 to 1830 m. Six reservoirs are in development. This study concentrates on projects in a carbonate formation that is a substage of the early Pennsylvanian Period. This formation is highly heterogeneous with closely underlying water. Permeability of the reservoir is approximately 43 md; reservoir pressure is 1,000 psi, and oil density is 0.891 g/cm3. Two adjacent well candidates with identical reservoir properties were selected for the study, with a distance between wells of approximately 136 m. Net oil thickness in Well A is 4.4 m and 3 m in Well B. Mechanical Radial Drilling Technology The technology described by the authors uses mechanical radial drilling with a slim mud motor. The technology allows the drilling of a network of radial channels up to 15 m long with up to four channels of different trajectories on one level. The technical system features a modular construction for ease of assembly at the wellhead area and increased operational efficiency. The main elements of the technical system include the following: - Pipe pusher connected at the top with an overflow valve module and, at the bottom, with a guiding device connected by means of a hydraulic pusher - Flexible pipe assembly with a small (nonstandard) sectional mud motor - Drilling bit (milling cutter for window cutting) - Special whipstock and an anchor module with an orienting funnel connected from below to the pipe frame

Customized Solutions for Coiled Tubing Interventions in the Bolivian Sub-Andean Basin

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202620, “A Review of 25 Coiled Tubing Well Interventions: Customized Solutions for Bolivian Sub-Andean Basin,” by Jovanny A. Hernandez, SPE, Luis F. Antelo, SPE, and Carlos D. Rodriguez, Halliburton, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Fields in the Bolivian Sub-Andean Basin are remote and difficult to access. The producing zones include the country’s most challenging wells, with depths of up to 26,000 ft, with high pressure/high temperature (HP/HT), high gas cut, crossflow, dogleg severity, and well-access restrictions. The complete paper reviews 25 coiled tubing rigless well interventions (CTRWI) to extend the life of those wells, including operations involving nitrogen (N2) lift, acid wash, milling, shifting sleeves, setting packers, stimulation, velocity strings (VS), and fishing. Introduction CTRWI in Sub-Andean Basin fields had not been implemented historically because of limited road access to the fields, lack of available equipment with high technical capabilities, high pressure, and well depth. Beginning in 2017, however, operators evaluated the risk and elected to perform CTRWI involving stimulation, cleanout, N2 lift, fishing, VS jobs, and other techniques. Equipment with specialized capabilities was requested to address the operational requirements and the ability to travel on the remote roads while respecting transit regulations limiting maximum weight to 55 tons. The challenges to transporting equipment economically include - Transportation of large reels of 2⅞-in. coiled tubing (CT) string to complete dual-sectioned VS installations - Transportation of CT unit with 6,600 m of 1¾-in. CT string (weight of less than 55 tons) - Continuously moving large volumes of N2 to the field Wells in these fields were drilled no more than 10 years ago. The majority were built with smart completions, several production layers separated with swell packers and flowing through sliding sleeves configured with the same direction of actuation for opening and closure. Completions are configured with production tubing sizes of 7, 5, 4½, and 3 in. The tubing and accessories are made from chrome 13 because of the presence of carbon dioxide in the production fluids. The region includes some exploratory fields having HP/HT conditions and mature fields with declining production. These wells are important for both the operators and the local government because their production represents more than 50% of national production. On-Site Laboratory Testing Characteristics of produced formation water and mineralogy tests of water samples helped identify a calcium carbonate (CaCO3) scale type. Because CaCO3 scale is known to be acid-soluble, a tailored acid-treatment system was selected with a static formation temperature between 220 to 286°F. On-site laboratory tests using a combination of 13% acetic and 9% formic retarded acid treatment systems were applied to the samples obtained, and results of a solubility test were observed. The selected treatment was demonstrated to be highly effective at dissolving CaCO3 scale according to the test made at the wellsite. High confidence was placed in the test results of the acid-treatment sample because dissolution was above 85% in a 4-hour test period under static well temperature.

Expended Polystyrene (EPS) Waste as Sorbent for Crude Oil Spill Cleanup: From Laboratory Experiments to Field Application

EPS is a major constituent of plastic waste. Reuse of waste EPS which is non-biodegradable, to useful products is a way of effective waste management. Oil is one of the most important energy sources but oil spill accidents often take place during the oil utilization process, resulting in threats to the environment. We reported the use of EPS waste to obtain an adsorbent material to cleanup crude oil spill from water. The effects of major factors such as sorption time, adsorbent surface areas, kind of surface (smooth or rough) and thermo-modification and mechanical modification (punching holes) were investigated on laboratory experiments and presented at ADIPEC 2014( Abu Dhabi International Petroleum Exhibition & Conference, 10-13 Nov., 2014, Session 52 Environment, SPE 172000-MS). The laboratory experiments carried out with about 0.9 g EPS sorbent for oil sorption times of 5 to 120 min at 350 g oil only and at 100 g oil over 500 mL water. The sorbent were punched with holes of 1.65 mm diameter. To verify the above laboratory experiments a field study for oil spill cleanup at crude oil pond from a rupture pipeline in Basrah was conducted. About 40 g EPS waste of small pieces (0.100-0.200 g) packed in 40x30 cm mesh net plastic bags. More than 40 bags were placed on the surface of a pond containing the spill crude oil over water. The pond was of about 6 meter diameter with oil layer of about 1.0 cm thickness. The bags were agitated manually after placing it on the oil surface to increase oil distribution to all EPS pieces. Oil sorption Capacity (OSC) of EPS in the field application increased with the increasing of the sorption times. The oil sorption was measured after 30 min sorption time and then every 15 min till 150 min. OSC of 43- 53 g oil/ g EPS sorbent for a sorption time of 30- 150 min respectively, were determined. The OSC are about 4 times the maximum OSC of the laboratory tests. The increasing in OSC of field application over laboratory tests due to utilization of all EPS 6 surfaces in place of one surface in laboratory tests, using lower density EPS and high density crude oil. The use of EPS waste in oil spill cleanup will reduce pollution in two ways, remediation of oil spill and reduce the landfill area due EPS waste

Hole-Cleaning Fibers Improve Cuttings-Carrying Capacity

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203147, “Investigating Hole-Cleaning Fibers’ Mechanism To Improve Cutting Carrying Capacity and Comparing Their Effectiveness With Common Polymeric Pills,” by Mohammad Saeed Karimi Rad, Mojtaba Kalhor Mohammadi, SPE, and Kourosh Tahmasbi Nowtarki, International Drilling Fluids, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Hole cleaning in deviated wells is more challenging than in vertical wells because of the boycott effect or the eccentricity of the drillpipe. Poor hole cleaning can result in problems such as borehole packoff or excessive equivalent circulating density. The complete paper investigates a specialized fibrous material (Fiber 1) for hole-cleaning characteristics. The primary goal is to identify significant mechanisms of hole-cleaning fibers and their merits compared with polymeric high-viscosity pills. Hole-Cleaning Indices Based on a review of the literature, most effective parameters regarding hole cleaning in different well types were investigated. These parameters can be classified into the following five categories: - Well design (e.g., hole angle, drillpipe eccentricity, well trajectory) - Drilling-fluid properties (e.g., gel strength, mud weight) - Formation properties (e.g., lithology, cutting specific gravity, cuttings size and shape) - Hydraulic optimizations (e.g., flow regime, nozzle size, number of nozzles) - Drilling practices (e.g., drillpipe rotation speed, wellbore tortuosity, bit type, rate of penetration, pump rate) In this research, rheological parameters and parameters of the Herschel-Bulkley rheological model are considered to be optimization inputs to increase hole-cleaning efficiency of commonly used pills in drilling operations. The complete paper offers a detailed discussion of both the importance of flow regime and the role of the Herschel-Bulkley rheological model in reaching a better prognosis of drilling-fluid behavior at low shear rates. The properties of the fibrous hole-cleaning agent used in the complete paper are provided in Table 1. Test Method Two series of tests were performed. The medium of the first series is drilling water, with the goal of evaluating the efficiency of Fiber 1 in fresh pills. The second series of tests was per-formed with a simple polymeric mud as a medium common in drilling operations. Formulations and rheological properties of both test series are provided in Tables 4 and 5 of the complete paper, respectively.

Drilling Dynamics, Mechanical Specific Energy Data Help Drill Record Extended-Reach Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203335, “Using MSE and Downhole Drilling Dynamics in Achieving a Record Extended-Reach Well Offshore Abu Dhabi,” by Nashat Abbas and Jamal Al Nokhatha, ADNOC, and Luis Salgado, Halliburton, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Complex extended-reach-drilling (ERD) wells often present challenges with regard to geological aspects of data requirement and transmittal, reactive geosteering response times, and accuracy of well placement. Such scenarios may require innovative approaches in Middle East carbonate reservoirs. The objective of the complete paper is to illustrate that, by assessing the details of reservoir geology and key operational markers relevant for best practices, drilling approaches can be customized for each reservoir or scenario. Reservoir Background and Geology The planned reservoir section is a single horizontal of approximately 25,000-ft lateral length at a spacing of 250 m from adjacent injectors. The well was drilled from an artificial island. Field A, a shallow-water oil field, is the second-largest offshore field and the fourth-largest field in the world. Horizontal drilling was introduced in 1989, and an extensive drilling campaign has been implemented since then using steerable drilling technologies. This study is concerned only with wells drilled to develop Reservoir B in Field A, which contributes to the main part of initial oil in place and production. The thick limestone reservoir is subdivided into six porous layers, labeled from shallow to deep as A, B, C, D, E, and F. Each porous layer is separated by thin, low-porosity stylolites. The reservoir sublayer B, consisting of approximately 18-ft-thick calcareous limestones, was selected as the target zone for the 25,420-ft horizontal section. ERD, constructed on artificial islands, began on 2014 with a measured depth (MD)/true vertical depth (TVD) ratio approaching 2.2:1 or 2.4:1. A recent ERD well, Well A, was drilled at the beginning of 2020 with a MD/TVD ratio of 5:1. This value is a clear indication of progressively increasing challenges since the start of the project. Mechanical specific energy (MSE) has long been used to evaluate and enhance the rate of penetration (ROP); however, its use as an optimization tool in ERD wells has not been equally significant. This may have been mostly because of historical use of surface-measured parameters, which do not necessarily indicate the energy required to destroy the rock, particularly in ERD wells. Using optimization tools as part of the bottomhole assembly (BHA) downhole close to the bit provides actual weight-on-bit (WOB) and torque-on-bit (TOB) applied to the drilling bit to destroy the rock and, thus, results in more-representative MSE measurements to optimize drilling parameters and ROP in ERD wells.

Operator Develops Fully Smart Onshore Field

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 203461, “Digitalization in the Oil and Gas Industry—A Case Study of a Fully Smart Field in the United Arab Emirates,” by Muhammad Arif and Abdulla Mohammed Al Senani, ADNOC, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9–12 November. The paper has not been peer reviewed. One of the first oil fields in the UAE to be fully operated remotely is in the southeast region, 250 km from Abu Dhabi. The complete paper discusses the development and commissioning of the field, which is the first smart field for ADNOC Onshore. The designed and applied technology facilitated unmanned operation of the field from downhole to export. Introduction Oilfield digitalization encompasses gathering real-time and non-real-time data from wells, flow lines, manifolds, stations, and water injection facilities; analysis of the data using algorithms, flowcharts, plots, and reports; and user access to this data on user-friendly screens. This allows engineers to focus on interpretation of data vs. searching, organizing, and formatting the data. In the bigger picture, the data collected will lead to conclusions and set bases for important decisions for similar projects in the future, enabling a lesson-learning approach to design new oil fields. The accumulated theoretical and practical research results of smart-field implementation require analysis and synthesis to maintain perspective of the entire project. Both were applied in the Mender field, which is the subject of the complete paper. Problem Statement The Mender parent field has been producing since 2013 with minimal digitalization for wellheads. Wells are not fit-ted with remote sensors, and operators have been visiting the wells to collect data using analog gauges. Collected data are stored in computers or as hard copies. Some critical data is lost, which affects decision-making. The new Mender field is 50 km from the parent field and is in a sensitive area close to international borders. The field area is a wildlife reserve for various endangered animals. The nature of operations is highly critical because of concentrations of hydrogen sulfide (H2S) that could jeopardize employees’ health and safety.

Successful Fishbone Stimulation Completion for an Onshore Oil Field, United Arab Emirates

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 203086, “First Successful Fishbone Stimulation Completion in Onshore Oil Field in the United Arab Emirates,” by Fernando Quintero, Noor Talib, and Alvaro Jimenez, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. The complete paper describes the operator’s first implementation of fishbone stimulation technology. A multidisciplinary team analyzed the operational procedures, conducted risk assessments and logistical studies, and established contingency plans, technical requirements, and technical limitations. The deployment of the equipment and the production results were a success, overcoming hazard risks and uncertainties and closing gaps from previous, partially effective applications. According to the authors, fishbone stimulation technology will help increase productivity in a well too risky to be hydraulically fractured and beyond the reach of coiled tubing. Background As the industry seeks dynamic changes and novel ideas to increase the productivity of tight, thin reservoirs, fisbone stimulation represents a lower-risk and -cost solution to ensure deep connectivity with the reservoir in situations in which traditional conventional stimulation practices have reached their potential boundaries without achieving crude recovery objectives. The project described in the complete paper is part of a series of field-development projects in United Arab Emirates onshore fields to exceed expectations of the committed production targets. This trial has taken the form of a pilot test for implementing fishbone stimulation for a short duration in other onshore fields. The new approach has already enhanced production up to three times and has provided wellhead pressure support. While this marks a successful beginning, more field trials will be needed to implement wider use of this technology. Fishbone completion stimulation technology is based on the use of subs that are installed in uncemented liner in which each sub features four small-diameter, high-strength tubes called needles (Fig. 1) that can be extended up to 40 ft in length by bullheading acid (Fig. 2). The objective of the technology is to increase well productivity and injectivity by the needles by connecting natural fractures and vertical layers and increasing reservoir contact and effective well-bore radius. To address the deployment challenge, a risk assessment was under taken with the active participation of a multidisciplinary team, including members from the operator (drilling and asset team) and the service company, to ensure that all required precaution inputs were considered. The risk assessment was conducted by identifying the situations that could threaten the deployment and full extension of the needle, a critical aspect of the job. The complete paper describes primary factors such as the following: - Sub-assembly preparation - Running liner to total depth and setting liner hanger - Mixing and handling hydrochloric acid (HCl) - Pumping the acid job - Fluid losses after the acid job - Cleanup runs with fishbasket cutting assembly

Tubing Failure in HP/HT Wells Investigated and Mitigated

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 20136, “Research and Application of Fracture Failure Control Technology for 13Cr Tubing in HP/HT Gas Wells,” by Lei Ma, Hongtao Liu, and Hailong Geng, PetroChina, et al., prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. Super 13Cr-110 tubing used in high-pressure, high-temperature (HP/HT) gas wells in the Tarim oil field has experienced numerous failures. After a series of investigations for root-cause analysis, the conclusion was that fracture of the tubing mechanistically is categorized as stress corrosion cracking (SCC) and is closely related to the application of phosphate-based completion fluid. Further tests indicated that Super 13Cr (S13Cr) tubing specimens experienced SCC with phosphate-based completion fluids contaminated with mud and oxygen, whereas formate-based completion fluid is compatible with S13Cr tubing. At present, 55 HP/HT gas wells in the field have used formate-based completion fluid with no tubing string fracture. Introduction Compared with the Gulf of Mexico, the North Sea, the South China Sea, the Qiongqiong Basin, and various Chinese oil and gas fields, the oil pipelines in the Tarim field are among the most difficult with regard to service conditions, which are characterized by extreme operating conditions such as high pump pressure and large displacement reform. Construction and high-yield alternating loads on tubing string and joint and a harsh, corrosive environment [chloride content greater than 80 000 mg/L, carbon dioxide (CO2) partial pressure greater than 1 MPa, and the presence of fresh and residual acid] pose significant challenges to the safe service of the tubing string. In the early stages of production, S13Cr oil pipe was selected as the completion string of the HP/HT gas well in the Kuqa mountain front, but in recent years, the S13Cr-110 pipe of the HP/HT gas well in the Tarim field has been continuously fractured. Failure accidents have caused serious economic losses. In the complete paper, through lateral comparison analysis of the failed tubing and indoor simulation experiments, the cause of the tubing fracture is discovered, solution measures are initiated, and good application results are achieved. Comparative Analysis of Oil-Pipe Failures Comparative Analysis of Fracture Macroscopic Morphology. When comparing the macroscopic topographic maps of oil-pipe failures seen in six studied wells, fracture locations of three wells are located in the coupling, while fracture locations of the other three wells are located on the body. In five wells (Wells A through E), the tubing fracture is neat, indicating brittle fracture with no plastic deformation. Well F, however, has a visible longitudinal crack on the surface of the tubing, and many burrs are visible at the fracture. Comparison and Analysis of Working Conditions of Failed Tubing. Through comparative analysis, it was determined that five of the six wells have under-gone acidification. The service shaft temperature, pressure, CO2 content, and formation water salinity of the failed wells differ, but, in five of the six wells, the tubing was exposed to a phosphate-based completion fluid.

Formation Evaluation Workflow Assesses Mass-Transport Complex Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203016, “Formation Evaluation in Mass-Transport Complex Reservoirs,” by Ulises Bustos, Schlumberger; Carlos Duran, Petróleos Sudamericanos; and Alvaro Chapellin, Schlumberger, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. Mass-transport deposits (MTDs) are sedimentary, stratigraphic successions remobilized after initial deposition but before substantial lithification and transported downslope by gravitational processes as non-Newtonian rheological units. In the complete paper, the authors present an openhole advanced formation-evaluation approach that enables assessment of tight-matrix and natural-fracture systems at a level not previously accomplished in these types of geological formations. Introduction The considered wildcat project by Petroleos Sudamericanos is in the Lower Magdalena Valley hydrocarbon province in Colombia. From a stratigraphic point of view, the targets belong to tertiary deposits from the lower Neogene. Gravity-driven processes are complex and include creep, slide, slump, debris flow, and multiphase granular flows. The remobilized sedimentary deposits resulting from these processes are called MTDs or mass-transport complexes (MTCs) and are the main target job. Overlaying a crystalline basement, four MTC cycles were identified (although the present work only covers three MTC cycles) deposited in shallow marine environments. Each cycle consists of quartzite; phyllite; and schistose metamorphic rocks, largely gneiss with strong milonitization effects and foliated tremolitic marble in the top of the sequence. A summary of these types of rock is provided in the complete paper. The non-Archie nature of these rocks represents a challenge for formation evaluation. For reducing these uncertainties, a volumetric model with spectros copy dry-weight elements and nuclears was created that enabled solution of the total porosity, which was then benchmarked against the lithology-independent total nuclear magnetic resonance (NMR) porosity. The saturation computation was achieved with the fast neutron cross section method (FNXS) for the gas component and with total carbon for the liquid hydrocarbon fraction. The natural fracture system was analyzed with borehole image logs and with radial sonic-based dispersion analysis. The integration of matrix and natural-fracture assessment provided a robust formation evaluation that enabled identification of the main interest zones across the MTC cycles. Multifunction Spectroscopy for Matrix Analysis The multifunction spectroscopy tool is 1.72 in. in diameter and 18.3 ft long, consisting of a pulsed neutron generator and four detectors. The first detector is the compact neutron monitor, sensitive to fast neutrons and located adjacent to the high-output pulsed neutron source, measuring neutron output with high accuracy and precision. The second (near) and third (far) gamma-ray detectors are used for inelastic and capture spectroscopy measurements. The fourth and farthest-spaced detector (deep) uses an yttrium aluminum perovskite scintillator, which is involved in gas detection and assessment. The nuclear spectroscopy measurement is performed in energy and time domains; both aspects are described in detail in the complete paper.

Extensive Well-Testing Operations Provide Insight Into Khuff Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203441, “Lessons Learned From Extensive Well-Testing Operations in Khuff Formations Offshore Abu Dhabi,” by Florian Hollaender, SPE, Schlumberger, and Mahmoud Basioni and Ahmed Yahya Al Blooshi, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. An extensive appraisal campaign was performed in the Khuff reservoirs offshore Abu Dhabi, with multiple appraisal wells drilled in different fields. Those wells were evaluated using detailed logging campaigns and then subjected to well tests, usually through drillstem testing for targeted intervals. The interpretation of well tests, combined with advanced petrophysical analysis, formation-test data, and production logs, provided insight into the nature of the Khuff reservoirs. A wide range of responses was observed, from tight to highly productive, but not necessarily with clear previous indications of deliverability or inflow intervals. Overview of the Khuff Formations The key characteristics of the Khuff formations offshore Abu Dhabi have been well-documented in previous work and can be summarized by the following: Low porosity and permeability carbonate reservoirs, where natural fractures are critical contributors to flow Properties vary widely laterally, with significant uncertainty regarding connectivity Variations in stress and petrophysical properties can be significant and affected by diagenetic and tectonic history These reservoirs present significant challenges for development planning. Previous studies have shown that it can be difficult to relate production performance to standard petrophysical analysis directly and that the presence of fractures - in particular, critically stressed fractures - in the vicinity of the wellbore is an essential factor for production performance. Productivity also was found to vary by several orders of magnitude within the same reservoir depending on the field and lateral location of a given well. The presence of natural fractures has been recognized as a major contributor to flow in tight gas reservoirs; however, this raises several questions related to assessing formation potential. First, the nature of the fractures must be evaluated. Some will contribute to production, while others will remain sealed. Equally importantly, identifying zones with promising porosity developments is not a solid indicator of production expectations. Well-Test Observations With more than 20 drillstem tests performed in the Khuff reservoirs during a 4-year period, the first observation is the wide range of reservoir responses encountered, with an apparent lack of consistency within a given reservoir or field.

Implementation of an Intelligent Drilling Automation System in the Middle East

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 203251, “Drilling in the Digital Age: Harnessing Intelligent Automation To Deliver Superior Well-Construction Performance in a Major Middle Eastern Gas Field,” by Brennan Goodkey, Gerardo Hernandez, and Andres Nunez, Schlumberger, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. While breakthroughs in digital technology have rewarded many industries with a step change in productivity and efficiency during the past decade, the drilling industry has yet to benefit on a large scale from these advances. The complete paper details the introduction of a drilling automation system (DAS) to deliver superior well-construction performance in a major gas field in the Middle East. The DAS was deployed on two onshore gas drilling rigs. The paper discusses the technology itself, the deployment process, implementation challenges, the agile development model, and the results achieved. Introduction In 2018, Schlumberger partnered with a major Middle Eastern national oil company on one of the world’s largest lump-sum, turnkey gas-well-delivery projects, where drilling operations had already been optimized by targeting high-impact, low-effort areas of opportunity. Drilling automation was pursued to achieve an improvement in performance, specifically to shift the technical limit and to minimize the frequency of service incidents that could cost days of nonproductive time (NPT). An in-house solution under development for some time was designed to take control of the rig’s surface equipment to automate and optimize most drilling tasks and to generate value in the following areas: Automation of drilling actions to perform exactly as planned, within the safe limits of operation, by eliminating the inconsistency of manual operation and its susceptibility to human factors Identification and mitigation of drilling dysfunctions that could lead to costly tool failures and incidents by using intelligence engines that would adapt drilling parameters continuously for best performance Technology Overview The DAS was developed as the execution component of a well-construction platform designed to link planning and execution. The planning component allowed for all well-design stakeholders to collaborate online and create the well plan simultaneously. Once prepared, the plan would be exported to the rig as a machine-interpretable digital drilling plan that the DAS could digest. With the validation of rig personnel, the DAS would then take control of a selection of drilling actions and execute exactly as instructed in the well plan. While drilling, extensive information would be collected to serve as a vehicle to drive performance when planning future wells. In the deployment summarized in the complete paper, a pilot version of the drilling automation module was deployed as a standalone product. The key objectives of design included three categories - dynamic planning, safety and resilience, and interoperability.

Estimation of net oil and gas reserves and sensitivity analysis of influencing factors for net present value under royalty & tax contracts – a case study on X project, Kazakhstan

The Royalty & Tax Contract is one of the most common cooperation modes in the international petroleum industry. Under this mode, contractors take the share of net oil and gas reserves in kind, and pay royalties, income taxes and other taxes/fees to the landowner. The net reserves owned by a contractor refer to the remaining economical recoverable reserves that the contractor can obtain during the remaining contract period, and represent the contractor’s actual revenue. Taking the XX project in Kazakhstan as an example, this paper presented the method for estimating net oil and gas reserves under the Royalty & Tax Contract, discussed how the production, decline rate, development plan, oil prices, costs and taxes affect net reserves from the technical, economic, commercial and engineering perspective, and made sensitivity analysis of the most critical influence factors like oil production, oil prices, operation expenditure and investment. Finally, some development optimization and evaluation strategies were proposed to maximize the contractors’ economic benefits.

Cased-Hole Standalone Evaluation Succeeds in the Absence of Openhole Data

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 202894, “Cased Hole Standalone Evaluation: Breaking the Barrier To Successfully Evaluate Challenging Deep Carbonate Reservoirs,” by Pradeep Menon and Carey Mills, ADNOC, and Suvodip Dasgupta, SPE, Schlumberger, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. Accurate petrophysical evaluations (formation lithology, porosity, and water saturation) are essential in characterizing potential reservoir zones and estimating resources in place. Typically, these evaluations rely on acquisition of openhole logging measurements; however, this is not always possible. The complete paper outlines two examples from tight gas reservoirs in two separate fields offshore Abu Dhabi in which openhole data could not be acquired and petrophysical analysis was undertaken using cased-hole log data. These evaluations successfully identified gas-saturated porous intervals in each well, one of which was successfully flow-tested. Introduction A growing need exists to increase gas production in the UAE. As a result, specific gas-production targets have been mandated from development of currently undeveloped deep gas carbonate reservoirs such as the Permo-Triassic Khuff formation, the middle Jurassic Araej formation, and the Permian Pre-Khuff Unayzah and Berwarth formations. Recent appraisal wells have aimed at evaluating these reservoirs systematically by acquiring a good suite of openhole logs, cutting conventional cores, and conducting well-testing operations. These well data are combined with an evolving regional understanding to better assess and ultimately develop these complex formations. An accurate petrophysical evaluation requires the petrophysicist to develop a realistic evaluation of formation lithology, porosity, and water saturation. These parameters provide the foundations for further work such as static modeling stands, and they must be robust. The Upper Khuff is composed of dolomite occasionally grading to calcareous dolomite with minor interbeds of claystone and anhydrite. In core and cuttings, the dolomite in the uppermost section exhibits a grainstone texture with poor intercrystalline/intergranular porosity. The Lower Khuff is composed of very hard dolomite in part grading to calcareous dolomite, medium-to-dark grey-brown in places, with occasional very-fine-to-medium grainstone texture and very poor intercrystalline porosity. In this paper, the Upper and Lower Araej members are interpreted to have been deposited in an open, marine- circulation shelfal environment, while the Uweinat member is considered to have been deposited in a more- restricted circulation setting with-in a similar shelfal environment. The Barrier Openhole logging generally is the preference for formation evaluation because it represents the simplest environments and benefits from a comprehensive list of available measurements. The variety of tools and diversity of output data available make openhole log acquisition the gold standard for formation evaluation. However, in certain situations in which openhole logging is not possible because of borehole conditions (re-entry of old cased wells, wellbore instability, over-pressure), no option exists other than acquiring petrophysical data in a cased-hole environment.

Deep-Learning Technique Monitors Well-Testing Burner Efficiency

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19714, “Deep Learning for Monitoring Well-Testing Burner Efficiency,” by Darine Mansour, SPE, Hakim Arabi, and Yingwei Yu, SPE, Schlumberger, et al., prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. During well-testing operations, incorrect burner combustion could have an adverse effect on the environment or personal safety. Combustion efficiency is assessed by personnel who observe the flame. This practice lacks consistency and poses challenges, including environmental and safety considerations and issues with data. In the complete paper, the authors propose a solution that uses a deep neural network that learns from flame videos to define the quality of the combustion. The results are promising and show that this solution is a good candidate for real-time burner-efficiency monitoring and automatic alarm triggering and optimization. Introduction Automation of the evaluation of combustion efficiency would promote consistent combustion efficiency and timely reaction to undesirable combustion. In field operations, cameras are positioned for a direct view of the burner flames. The authors use a data set of video images captured by the cameras and labeled by domain experts as images of acceptable or undesirable combustion. The goal of the study is to automate human monitoring of the combustion by processing these images and classifying them automatically as images of acceptable or undesirable combustion. A supervised learning approach is applied to the problem. The approach consists of extracting the flame features from each image and feeding the features to a classifier that categorizes the combustion. The classifier is trained using the extracted features and labeled combustion images as input. The traditional approach to feature extraction is manual feature engineering, involving the extraction of handcrafted features using image-processing algorithms and domain knowledge. The process is tedious and time-consuming. Much effort is required to extract all relevant features in various contextual and environmental conditions. The extracted features are problem-dependent, and the process may require revisiting algorithms to adapt to new data that hold new features or new representations of existing features. Approach To achieve classification, a convolutional neural network (CNN) is trained using a data set of images labeled by domain experts. Using the image data set captured by well-testing cameras, a CNN with an architecture similar to VGG-16 that learns to extract powerful features from natural images is fine-tuned.

Geocognitive Technologies Improve Basin- and Petroleum-System Analyses

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 197610, “Application of Geocognitive Technologies to Basin- and Petroleum-System Analyses,” by Paolo Ruffo, Marco Piantanida, SPE, and Floriana Bergero, Eni, et al., prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Eni and IBM developed a cognitive engine exploiting a deep-learning approach to scan documents searching for basin geology concepts, extracting information about petroleum system elements (e.g., formation name; geological age; and lithology of source rocks, reservoirs, and seals), and enabling basin geologists to perform automated queries to collect all information related to a basin of interest. The cognitive engine succeeded in identifying the correct formations, lithologies, and geological ages of the petroleum systems with an accuracy in the range of 75 to 90%. Introduction While commercial databases often provide summary information about basins that can be extracted easily with queries or even interactive tools, the explorationist needs to integrate such information with more up-to-date and in-depth descriptions of structural and sedimentary events occurring in the basin, descriptions that can be found only in unstructured documents. Key information about basins can be scattered across paragraphs, tables, and image captions of hundreds of technical articles, or can be embedded within pictures. Even when exploiting a traditional search engine with the name of the desired basin, the results can be unsatisfactory: first, not all the results might be relevant; second, many different variants of the basin name are often used within publications. In the optimistic hypothesis that the subset of relevant documents is found by the search engine, all key concepts related to a basin need to be understood by the geologist by careful examination of the paper text and images. Moreover, even if the published information (structured and unstructured) on a basin is found, there are different opinions expressed by different authors, in addition to the uncertainty of the data itself (such as the age of a formation or the details of the geological evolution of the basin), so that multiple conceptual models of the basin can be drawn from the uncertain and scarce information available. Some of these conceptual models are more probable while others are less probable, but sometimes the latter happen to be economically more valuable. Therefore, recovery of all relevant information about a basin is crucial, but also important is the preservation of differing opinions about the data - what might be termed minority reports.

Dynamics Mechanism of Vulnerability for Petroleum Enterprises

This article analyses the dynamics mechanism of international petrochemical enterprises vulnerability and select the key factor of resources to establish a nonlinear dynamical model, which discovering the internal binding relationship between the number of big petrochemical enterprises vulnerability, the petroleum shortage ratio (<I>D</I>) and the petroleum occupancy ratio of the biggest enterprise (<i>q</i>). The results show that, as <I>D</I>><i>q</i>, the petroleum shortage ratio exceeds the occupancy ratio of the biggest international petrochemical enterprise in the international petroleum resource market, the following rules and characteristics exist in the evolution of petrochemical enterprises:(1) The biggest enterprise in the petrochemical system will inevitably decline. With petroleum shortage increasing, following the decline of the biggest petrochemical enterprise will be the second, the third-biggest petrochemical enterprises and so on. The number of big decline petrochemical enterprise will increase with the increase of the value of <I>D</I>/<i>q</i>. The time for the petrochemical enterprises to go decline will be from 50 to 500 days. (2) After an incident of petroleum shortage, the surviving petrochemical enterprises will go through three stages: (A) resisting stage. (B) resumption stage. (C) stable stage. The international petrochemical industry will strictly observe the even-odd or odd-even number symmetry law. If the shortage of petroleum leads to the decline of odd-number petrochemical enterprises, after the adaptability and stability, the petrochemical enterprise system will obey the even-odd number symmetry law, i.e. the former ordinal number petrochemical enterprises become bigger. If the decline petrochemical enterprise in this system is ranked even-number, after the adaptability and stability, the petrochemical enterprise will obey the odd - even number symmetry law, i.e. the former odd numbered petrochemical enterprise become bigger, but those former even numbered get smaller. We think that a petrochemical enterprise will continually develop and grow stronger in the petroleum competition, only if it seizes the petroleum shortage ratio and the occupancy of the biggest enterprise in the petroleum resource market, understands the even-odd or odd-even number symmetry law in the petroleum economical system and positions itself correctly.

Brief Analysis of Cost per Meter Management in Drilling and Well Completion Operations in Bohai Oilfield

The development of domestic offshore petroleum engineering is faced with opportunities and challenges under the situation dominated by the seller across the complex international petroleum market. The cost of drilling and well completion accounts for more than half of the budget, also directly affect the feasibility of offshore oilfield development. Therefore, to effectively improve the management level of offshore drilling and well completion, "speed, quality, production and efficiency" are the main problems faced by the workers. The meaning of cost management, and influencing factors, and the current status of drilling cost control has been introduced in this paper. The aim will be to provide reference value for the subsequent development of offshore oil drilling and well completion and the cost management of related oil industry.

Novel Geophone Array Measures Exact Location of Fluid Movement Behind Casing

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 197560, “Enhanced Well Remedial Decisions From Exact Location of Fluid Movement Behind Casing Identification,” by Marcel Croon, SPE, Perry Huber, SPE, and Jacob Wright, SPE, Weatherford, SPE, prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Historically, acoustic wellbore monitoring is among the primary methods of detecting fluid movement behind the casing. However, analysis of the complex acoustic environment in the wellbore can be challenging. A standard hydrophone noise tool is unable to measure flow directions (vertical and horizontal) and cannot detect low flow, low-pressure sporadic events, or multiple sources. The complete paper discusses a geophone array, including four, three-component geophones deployed by wireline, that provides a solution for this problem by creating a 3D map of the acoustic environment. Introduction Well-integrity issues such as a poor cement bond can lead to undesirable fluid movements behind the casing, which could have negative effects with regard to health, safety, and the environment. A detailed understanding of annular fluid movement is critical in identifying potential source locations for wells with surface-casing vent-flow (SCVF) issues. Applicable scenarios include the following: Planned well-intervention activities for wells with multiple-source vent/flow situations Confirming the presence of flow (gas/oil/water) behind the casing Identifying areas with suspected crossflow between zones Integrity confirmation for gas storage caverns or zones Identifying unwanted flow for well-abandonment activities Well abandonment is bound by stringent regulations in some countries where the testing and repair of SCVF and gas-migration (GM) issues before final abandonment are required. An ex-ample is western Canada, where surface casing vents must be tested through a bubble test at minimum. This involves connecting a small container with 2.54 cm of water using fittings to the surface casing vent and monitoring for gas bubbles for 10 minutes. Often the flow rates are very low (less than 35 cu ft/d) with minimal pressure buildup. If bubbles are detected during the monitoring period, the well is deemed to have a positive vent flow. Consequently, the source of the vent flow must be identified by a survey as approved by the energy regulator, which could be conducted by means of acoustic logs, temperature logs, or gas- isotope analysis. Additionally, GM measurements must be conducted before final abandonment in specific areas within western Canada but are recommended for all wells. The complete paper details this process.

Remote Monitoring Digitizes Asset-Integrity Management

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 197168, “Digitalize Asset-Integrity Management by Remote Monitoring,” by Mohamed Sahid, ADNOC, prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Monitoring of corrosion in process pipelines has always been of paramount importance in ensuring plant-asset integrity. Similarly, steam traps play an important role in ensuring steam quality and, thus, the integrity of critical assets in the plant. The complete paper discusses these two aspects of monitoring asset integrity - real-time corrosion monitoring and real-time steam-trap monitoring - as implemented by the operator. The authors highlight the importance of digitization by means of implementing wireless technology and making data available in remote work stations in real time. Real-Time Corrosion-Monitoring System Corrosion coupons and electrical resistance probes are among the most-tried and -tested methods to monitor corrosion, but the authors detail shortcomings of these systems, focusing their efforts on the option of using nonintrusive ultrasonic sensors for corrosion monitoring. Fixed ultrasonic thickness (UT) monitoring systems measure a localized thickness of vessel wall or pipe through the use of sound waves. They are the fastest method to measure wall thickness and wall loss reliably. The wall thickness is calculated from the reflection of the ultrasonic signal at both external and internal surfaces. UT systems normally include a transducer and a pulser/receiver. The type of transducer used for this application is the ultrasonic transducer, which can be either piezoelectric or variable-capacitive. The pulser generates short electric pulses of energy at a constant rate, which are converted by the transducer into short, high-frequency ultrasonic sound pulses. These pulses are then directed into the material. Any discontinuation or impurity in the path of the ultrasonic sound wave will be reflected and received by the transducer, transformed into an electric signal, and amplified by the receiver to be projected onto the display (in the case of portable UT instruments). Depending on the intensity shown on the display, information about the impurity or discontinuity, such as size, orientation, and location, can be derived accurately. The shortcomings of using portable UT sensors have been overcome by the introduction of permanent UT sensors, which provide wall-thickness measurement continuously at one location in real time. Because these sensors remain fixed at one location for years, it is possible to analyze corrosion at a single point over time, thus detecting early corrosion onset. Real-Time UT Gauging. The operator installed the real-time corrosion-monitoring system in its offshore associated gas (OAG) unit. A UK-based vendor provided UT sensors along with data-management and -viewing software to support data interpretation. Twenty locations were identified in various plants of the OAG unit on the basis of criticality and previously recorded corrosion levels.